Despite the downturn, plenty of development is underway in Southeast Asia. Audrey Raj sets out the detail.
Bach Ho oil field in Cuu Long basin. Photo from PetroVietnam.
Despite the fall in oil prices, Southeast Asia (SEA) will see investments in offshore projects, which are commercial at the current price of US$65/bbl.
The region, particularly rich in oil and gas in countries like Malaysia and Indonesia, will continue to be an increasingly important area for global offshore developments.
SEA has long been a center for construction and fabrication within the offshore market, while economic advancement and rising energy demand has spurred on technological development.
According to Infield Systems’ published content analyst, Catarina Podevyn, during the next five years, SEA is likely to see growth in the liquefied natural gas (LNG) sector, with the emergence of the floating LNG (FLNG) technology.
“Key FLNG projects include Petronas’ PFLNG-1 and PFLNG-2 units, while we also expect for expenditure to be required on Indonesia’s Abadi FLNG facility from 2018 onwards,” Podevyn says.
PFLNG-1. Photo from Petronas.
“Deepwater fields are forecast to comprise an increasing share of SEA’s capex demand up to 2020, with expenditure demand in deepwater to form 25% of total spending during the 2016-2020 timeframe,” she continues.
Driven by Malaysia, one key project is the Rotan field in the South China Sea, offshore Sabah. Petronas’ PFLNG-2 is being designed for this field to produce some 1.5 MTPA ton of LNG.
Offshore Indonesia, Podevyn expects significant deepwater developments as well, with the capital intensive Gendalo field holding the largest share of expenditure.
Gendalo field is part of the Indonesia Deepwater Development (IDD) project consisting of five fields, including Maha, Gandang, Gehem and Bangka.
Situated in the Kutal basin, IDD is known to be the deepest offshore project undertaken in Indonesia, sitting in waters ranging 610-1829m deep.
GlobalData’s Asia-Pacific senior upstream analyst Joseph Gatdula points out another emerging trend in the SEA offshore sector, which is the continuation of large scale projects already sanctioned and the commercialization of gas fields throughout the region.
“One such key bellwether will be the Lengo field also in Indonesia, which looks to capitalize on the local East Java gas market. But the final investment decision (FID) will heavily depend on the long-term contract prices currently under negotiation,” Gatdula says.
Located 197ft in the Bulu production sharing contract (PSC), the Lengo field operated by KrisEnergy is estimated to produce some 70 MMcf/d of gas.
Petronas engineers. Photo from Petronas.
Furthermore, a report by consulting firm Frost and Sullivan revealed that Malaysia and Indonesia are set to become the most lucrative markets in SEA’s offshore oil and gas services sector.
With both countries witnessing the highest exploration activities, they will become the largest markets for offshore support and pipeline services.
The report found that while global drilling, marine and pipeline support service markets collectively earned revenues of $200 billion in 2014, this is set to reach $241 billion in 2018.
“Despite the oil price situation, the SEA offshore oil and gas services market managed to generate revenues of $25 billion in 2014,” notes the firm’s energy and environmental consultant, Daniel Wicaksana.
“A lot of different players ranging from large multinational companies to medium- to small-sized regional and local companies have been driving total market revenues,” Wicaksana explains.
Issues and challenges
While aging offshore infrastructures and declining production are particular challenges in SEA, the Indonesian offshore sector lacks investment, Podevyn says.
Coupled with rising domestic energy demand, this has resulted in the country now facing the possibility of becoming a net gas importer by the end of the decade, despite being one of the leading global exporters of LNG.
PetroVietnam workers at Dai Hung oil field. Photo from PetroVietnam.
“While deepwater prospects within the region have been on the increase, we have seen a number of delays over the last eight months, although Infield Systems does not expect the current low oil price to prevail over the long-term,” Podevyn says.
“Deepwater development also brings with it operational and technical challenges, and in a region not traditionally associated with deepwater work, national oil companies (NOC) will have to work with experienced operators and contractors from outside the region,” she adds.
GlobalData expects operators to push equipment and service providers even harder in cost reductions in the offshore sector, as reflected by the significant drop in day rates for rigs in the region.
“We also anticipate operators maximizing the use of existing infrastructure to lower development costs, including the use of subsea tiebacks to develop new fields,” Gatdula says.
Growth and investment
Indonesia has potential to grow, with the caveat that it is dependent on a raft of potential changes instituted under new government initiatives, including the effort to reduce corruption.
Since, the Widodo government has reduced fuel subsidies and allowed free market approach to pricing of both gas and crude, Gatudala says this should raise prices and allow for better field economics.
“A planned license round for 2016 is also rumored to have the potential for significant changes in the fiscal terms needed to spur exploration and development within the 10-year window,” he says.
Indonesia is also expected to see the largest investment growth throughout the five-year timeframe with Infield Systems expecting a CAGR of 25% from 2016-2020.
“Investment demand is expected to be driven by the IDD development, although full operation of the project has been delayed as Chevron revises its development plans,” Podevyn explains.
“Other key projects to take place offshore Indonesia during the following five years, include East Natuna and the Eni-operated Jangkrik development.”
The East Natuna field in the Greater Sarawak basin north of Jakarta is developed by the Indonesian state-owned oil company, Pertamina and contains approximately 46 Tcf of gas.
Consisting of Jangkrik and Jangkrik Northeast fields, production start-up at the Jangkrik development project in the Makassar Strait is likely to begin in 2017.
Myanmar, too, is scheduled to have a round of licensing in 2016. According to the Ministry of Energy, the country has 104 oil and gas blocks, and only 19 out of the 51 offshore blocks are in operation.
In its move to attract more investors, last year Myanmar made changes to its oil and gas investment regulatory framework. Now, investors keen on deepwater blocks will not require local partnering, but shallow water explorers are called to find local partners.
According to the Myanmar Investment Commission, Myanmar has received more than $8 billion in Foreign Direct Investment (FDI) last fiscal year and the oil and gas sector drew $3.6 billion.
In 2014, 40 offshore and onshore blocks were awarded to industry players such as Chevron, Shell, Total, BG, Petro Brunei and PTT Exploration and Production (PTTEP).
Activities are expected to pick up towards the end of 2015 or early 2016, as some of the winners kick-start their seismic surveys.
Malaysia, Podevyn says, is expected to remain the largest market for offshore demand going forward to 2020 with a 37% market share of SEA capex demand during 2016-2020.
“However, going forward to 2020 Infield Systems actually expects a decrease in expenditure by a CARG of -5%. Key projects driving demand will include the Rotan FLNG development and the Petronas-operated Bokor field,” she says.
“Thailand will see a small increase in offshore capital expenditure over the 2016-2020 timeframe compared to the previous five years, with expenditure demand expected to peak in 2018.
“Ubon field is expected to be a key development for Thailand going forward, while the pipeline sector is likely to require the largest expenditure demand over the five-year period,” Podevyn adds.
Thailand is also attempting to reform its energy sector, with a delayed bid round due to occur in 2015. The delay was because of adjustments in the fiscal policy to improve conditions based on the current market.
“As part of this effort, Thailand has committed to definitively outline the concession renewal mechanism to assure operators of the long-term stability of currently producing supply,” Gatudala says.
Most of Vietnam’s oil production comes from the Cuu Long basin comprising of large oil producing fields with an estimated 3.37 billion bbl of potential crude oil.
Although it is one of the most difficult environments to explore, wells that once took about three months to drill can now be completed within six weeks because of advanced technologies.
Despite the drilling and geological challenges, PetroVietnam is looking to further explore the potentials of the area and is actively seeking investors.
Vietnam’s Block B – operated by PetroVietnam in the Malay-Tho Chu basin holding about 5 Tcf of gas and condensate – Gatudala says is slated to cost upwards of $10 billion.
“As the development plans come together, we anticipate a commercial decision later in 2016,” Gatudala concludes.